Hydrocarbons may be recovered from hydrocarbon-bearing formations by penetrating the formation with one or more wells. Hydrocarbons may flow to the surface through the wells. Conditions (e.g. permeability, hydrocarbon concentration, porosity, temperature, pressure, amongst others) of the hydrocarbon containing formation may affect the economic viability of hydrocarbon production from the hydrocarbon containing formation. A hydrocarbon-bearing formation may have natural energy (e.g. gas, water) to aid in mobilizing hydrocarbons to the surface of the hydrocarbon containing formation. Natural energy may be in the form of water. Water may exert pressure to mobilize hydrocarbons to one or more production wells. Gas may be present in the hydrocarbon-bearing formation (reservoir) at sufficient pressures to mobilize hydrocarbons to one or more production wells. The natural energy source may become depleted over time. Supplemental recovery processes may be used to continue recovery of hydrocarbons from the hydrocarbon containing formation. Examples of supplemental processes include waterflooding, polymer flooding, alkali flooding, thermal processes, solution flooding or combinations thereof.
In chemical enhanced oil recovery (cEOR) the mobilization of residual oil saturation is achieved through surfactants which generate a sufficiently (ultra) low crude oil/water interfacial tension (IFT) to give a capillary number large enough to overcome capillary forces and allow the oil to flow (I. Chatzis and N. R. Morrows, “Correlation of capillary number relationship for sandstone”. SPE Journal, Vol. 29, pp 555-562, (1989).
Compositions and methods for enhanced hydrocarbons recovery utilizing an alpha olefin sulfonate-containing surfactant component are known. U.S. Pat. Nos. 4,488,976 and 4,537,253 describe enhanced oil or recovery compositions containing such a component. Compositions and methods for enhanced hydrocarbons recovery utilizing internal olefin sulfonates are also known. Such a surfactant composition is described in U.S. Pat. No. 4,597,879.
U.S. Pat. No. 4,979,564 describes the use of internal olefin sulfonates in a method for enhanced oil recovery using low tension viscous water flooding. An example of a commercially available material described as being useful was ENORDET IOS 1720, a product of Shell Oil Company identified as a sulfonated C17-20 internal olefin sodium salt. This material has a low degree of branching. U.S. Pat. No. 5,068,043 describes a petroleum acid soap-containing surfactant system for waterflooding wherein a cosurfactant comprising a C17-20 or a C20-24 internal olefin sulfonate was used. In “Field Test of Cosurfactant-enhanced Alkaline Flooding” by Falls et al., Society of Petroleum Engineers Reservoir Engineering, 1994, the authors describe the use of internal olefin sulfonates in a waterflooding composition.
Barnes, et al. (SPE-129766-PP “Application of Internal Olefin Sulfonates and Other Surfactants to EOR. Part 1: Structure—Performance Relationships for Selection at Different Reservoir Conditions”, SPE Improved Oil Recovery Symposium, Tulsa, Okla., USA, 24-28 Apr. 2010) reported on the use of internal olefin sulfonate (IOS), in particular IOS 19-23 and IOS 20-24, based surfactant systems for chemical enhanced oil recovery applications showing the different optimal salinity for the several surfactant systems with different oil compositions. According to Barnes et al., optimal salinity is the salinity of the water phase provided to the reservoir, whereby equal amounts of oil and water are solubilized in a microemulsion. Barnes et al., refer to Winsor having first described microemulsion phase behavior as type I (oil in water), type II (water in oil) and type III (bicontinuous oil/water phase also known as a middle phase microemulsion). For anionic surfactants, increasing salinity causes a transition from Winsor type I to type III to type II. Optimal salinity is defined where equal amounts of oil and water are solubilized in the middle phase (Winsor type III) microemulsion. The method principle is to measure the volumes of water, oil and any emulsion phases at a particular test temperature as salinity is increased causing a transition in phase behavior from Winsor type I to type III to type II. The data from these phases are plotted against salinity and give oil and water solubilization parameters. At the optimal salinity an ultra low oil/water interfacial tension is attained where capillary forces are lowest which enables the “residual oil” trapped in the rock to be mobilized.
Determination of the optimal salinity of a mixture of surfactant, oil and brine is an essential step in providing the appropriate surfactant system for a particular crude oil reservoir. The salinity of the brine is often set by the availability of the brine at the location of the reservoir. For instance when sea water is used as the brine at an off-shore location there are little means to economically change the salinity of the seawater. Therefore, the focus is on selecting a surfactant system that can provide a Winsor III type micro-emulsion in combination with the available brine and crude oil. However, till now the process for determining the optimal salinity of a surfactant system with available brine and crude oil is predominantly based on trial and error, including the expensive and time consuming procedure of producing surfactants with a different optimal salinity.
There is a need in the art for a method to predict optimal salinity for a surfactant system and a particular crude oil in a crude oil reservoir.